Reduction of hydrogen ingress into vacuum insulated tubing

ABSTRACT

A vacuum insulated tubing including an inner pipe, an outer pipe concentrically arranged about the inner pipe such that an annulus is defined between the inner and outer pipes. A vacuum is drawn within the annulus, and a hydrocarbon-based coating is applied to at least one of the surfaces of the inner pipe or one of the surfaces of the outer pipe to reduce a rate of hydrogen migration into the annulus.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from Canadian Patent Application 3,048,201 filed 28 Jun. 2019 entitled REDUCTION OF HYDROGEN INGRESS INTO VACUUM INSULATED TUBING, the entirety of which is incorporated by reference herein.

FIELD

The present disclosure is related to wellbore tubing and, more particularly, to vacuum insulated tubing coated with a hydrocarbon based coating to reduce the rate of hydrogen permeation into the evacuated annulus.

BACKGROUND

One challenge in producing heavier density oil from hydrocarbon-bearing subterranean formations is that the oil is cold and, therefore, highly viscous (“heavy”) and difficult to extract. To mobilize cold hydrocarbon deposits heat is often added to the reservoir using thermal recovery techniques, which help lower the viscosity of the hydrocarbons and thereby enables the fluids to be pumped to the surface. Commonly implemented thermal recovery techniques include a number of steam-based heating methods, such as steam flooding or steam drive (SD), cyclic steam stimulation (CSS) or “huff-and-puff,” and steam assisted gravity drainage (SAGD), as well as various derivatives of these techniques. Additional thermal technologies exist now which supplement or replace the steam with lighter hydrocarbons to improve energy efficiency and effectiveness.

In a typical SAGD process, for example, two horizontal wellbores are drilled to penetrate a hydrocarbon-bearing reservoir. The wellbores are drilled generally parallel but vertically spaced apart from each other, with one wellbore being positioned above the other by about 4 to 10 meters. High-pressure steam is conveyed through the upper wellbore (commonly referred to as the “injector”) and discharged into the surrounding formation to heat and reduce the viscosity of adjacent oil, thus allowing the heated oil to flow through the formation under the force of gravity. The heated oil, along with any condensed steam (i.e. water), drains into the lower wellbore (commonly referred to as the “producer”), through which the collected oil and water are simultaneously pumped to the surface. As the steam is conveyed downhole to the reservoir and the heated production fluids are drawn uphole toward the surface, however, heat is continuously lost to the surrounding subterranean environment. Heat loss decreases the effectiveness of the injected steam in contacting and decreasing the fluid viscosity of the oil, which can adversely affect well productivity.

Methods to limit wellbore heat loss have included the use of gelled diesel or insulated packer fluids in an annulus and/or using cement with higher thermal insulation properties. These methods, however, have been less than satisfactory in the high temperature environments required for thermal operations. Another solution to minimize wellbore heat loss is the use or incorporation of vacuum insulated tubing (VIT), which provides an insulating vacuum break between the injector and producer tubing and the surrounding subterranean formations, seawater, etc. VIT typically consists of two concentrically oriented pipes of different diameters welded together with a vacuum drawn in the annular space defined there between.

While VIT provides superior insulative qualities as compared to bare steel tubing, one challenge faced with VIT is the decline in thermal insulating capacity due to the migration of hydrogen gas (H+) into the evacuated annulus. At elevated temperatures, hydrogen gas can pass through the carbon steel lattice structure of the VIT pipes and thereby reduce the insulative capacity of the VIT.

To mitigate the effects of migratory H+, chemical compounds commonly referred to as hydrogen “getters” are commonly used to absorb hydrogen that migrates through the steel into the evacuated annulus. Getters, however, are not infinite gas sinks and are often required to absorb hydrogen at a much greater rate than its infiltration from the surrounding annular environment, which constitutes an arguably infinite hydrogen source. Once the absorption capacity of the getter is exceeded, the vacuum within the VIT will proceed to degrade and insulative performance will decline.

SUMMARY OF THE DISCLOSURE

In some embodiments, a vacuum insulated tubing is disclosed and may include an inner pipe, an outer pipe concentrically arranged about the inner pipe such that an annulus is defined between the inner and outer pipes, and a vacuum drawn within the annulus. A hydrocarbon-based coating may be applied to at least one of an inner surface of the inner pipe or an outer surface of the outer pipe to reduce a rate of hydrogen migration into the annulus.

In some embodiments, a method is disclosed and may include flowing a heated fluid through a vacuum insulated tubing that includes an inner pipe and an outer pipe concentrically arranged such that an annulus is defined between the inner and outer pipes, a vacuum drawn within the annulus to create an evacuated annulus, and a hydrocarbon-based coating applied to at least one of an inner surface of the inner pipe or an outer surface of the outer pipe. The method may further include preventing heat loss from the vacuum insulated tubing to a surrounding environment with the evacuated annulus, and reducing a rate of hydrogen migration into the evacuated annulus with the hydrocarbon-based coating.

In some embodiments, a well system is disclosed and may include a tubing extending within a wellbore, wherein at least a portion of the tubing comprises vacuum insulated tubing that includes an inner pipe and an outer pipe concentrically arranged such that an annulus is defined between the inner and outer pipes, a vacuum drawn within the annulus, and a hydrocarbon-based coating applied to at least one of an inner surface of the inner pipe and an outer surface of the outer pipe. The hydrocarbon-based coating may operate to reduce a rate of hydrogen migration into the annulus.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.

FIG. 1 is a schematic diagram of an example well system 100 that may incorporate one or more principles of the present disclosure.

FIG. 2 is a cross-sectional side view of an example length of vacuum insulated tubing, in accordance with one or more embodiments of the disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure describe the use of coatings applied to vacuum insulated tubing (VIT) to reduce the rate of hydrogen permeation or migration into the evacuated annulus of the VIT and, therefore, increase the operational lifespan of the VIT. A coating may be applied to internal and/or external surfaces of the VIT. In some cases, the coating may be a hydrocarbon-based coating that operates to reduce hydrogen permeation by changing the spacing in the carbon steel lattice of the underlying VIT pipe such that it reduces the probability of hydrogen ions getting through the steel wall. The coating may also help reduce corrosion in the underlying VIT pipe, which is required to provide the electrons needed for the hydrogen ions (H+) to mate and form H₂ gas within the evacuated annulus.

FIG. 1 is a schematic diagram of an example well system 100 that may incorporate one or more principles of the present disclosure. In the illustrated embodiment, the well system 100 is configured for producing and/or recovering hydrocarbons using steam assisted gravity drainage (SAGD). It will be appreciated, however, that the principles and embodiments discussed herein may be equally applicable to other types of hydrocarbon recovery operations or any other application where insulated tubing is required, without departing from the scope of the disclosure. For example, the principles disclosed herein may alternatively be applied to any thermal hydrocarbon recovery techniques including, but not limited to, expanding solvent steam assisted gravity drainage (ES-SAGD), steam flooding, steam drive, cyclic steam stimulation (CSS), liquid addition to steam for enhancing recovery (LASER) with CSS, heated light hydrocarbon injection, vapor extraction (VAPEX), heated VAPEX, cyclic solvent processing (CSP), thermal-solvent injection (i.e., solvent additive versions of SAGD, ES-SAGD, and CSS), any combination thereof, or any derivatives thereof. The principles disclosed herein may also be applicable to any geothermal application that uses VIT.

As illustrated, the well system 100 includes an injection wellhead 102 a positioned on the earth's surface 104, and an injection wellbore 106 (alternately referred to as an “injector”) extends from the injection wellhead 102 a to penetrate a subterranean formation 108. The injection wellhead 102 a may include a wellhead installation, or a similar facility, and the injection wellbore 106 may be drilled into the subterranean formation 108 using any suitable drilling technique. In some cases, the injection wellbore 106 may extend in a substantially vertical direction away from the earth's surface 104 over a vertical injection wellbore portion 110. At some point, the vertical injection wellbore portion 110 may deviate from vertical and transition to a horizontal injection wellbore portion 112.

The well system 100 further includes a producer wellhead 102 b (e.g., a wellhead installation, or the like) also positioned on the earth's surface 104, and a producer wellbore 114 (alternately referred to as a “producer”) extends from the producer wellhead 102 b to penetrate the subterranean formation 108. Similar to the injection wellbore 106, the producer wellbore 114 may be drilled and extend in a substantially vertical direction away from the earth's surface 104 over a vertical extraction wellbore portion 116, but may eventually deviate and transition to a horizontal wellbore portion 118. The horizontal portions 112, 118 of the injection and producer wellbores 106, 114 may extend generally parallel to one another and may be vertically offset from each other.

While the injection and production wellheads 102 a,b are depicted in FIG. 1 as land-based rigs, the principles of the present disclosure could equally be applied to any sea-based or sub-sea application where either wellhead 102 a,b may be replaced with a floating platform, a sea-based platform, a sub-surface wellhead installation, or any combination thereof.

The well system 100 may further include an injection tubing 120 a extending from the injection rig 102 a and into the injection wellbore 106, and a production tubing 120 b extending from the production rig 102 b and into the producer wellbore 114. The injection and production tubings 120 a,b may comprise multiple lengths of pipe connected end to end. Example types of pipe that may help make up the injection and production tubings 120 a,b include, but are not limited to, casing, liner, drill pipe, production tubing, wellbore tubulars, or any combination thereof. Accordingly, in at least one embodiment, one or both of the injection and production tubings 120 a,b may comprise casing that lines the walls of the injection and production wellbores 106, 114, respectively, without departing from the scope of the disclosure.

One or more injection tools 122 may be coupled to the injection tubing 120 a and may be used to discharge (inject) a heated fluid 124 (e.g., a high-energy fluid) into the surrounding subterranean formation 108 from the injection tubing 120 a. The heated fluid 124 may comprise, for example, steam, but could alternately comprise other liquids or gases including, but not limited to oils, water, solvents, carbon dioxide, nitrogen, methane, a light hydrocarbon, or any combination thereof. In some embodiments, the heated fluid 124 may comprise any fluid (e.g., gas or liquid) that contains hydrogen atoms. One or more production tools 126 may be coupled to the production tubing 120 b and may be used to receive hydrocarbons 128 (e.g., oil) from the surrounding subterranean formation 108 and convey the hydrocarbons 128 into the production tubing 120 b for production.

In some applications, one or more wellbore isolation devices 130 (e.g., packers, gravel pack, collapsed formation, or the like) may be used to isolate annular spaces of both the injection and production wellbores 106, 114. More specifically, the wellbore isolation devices 130 may substantially isolate separate injection and production tools 122, 126 from each other within the corresponding injection and production wellbores 106, 114. As a result, the heated fluid 124 may be injected into the formation 108 at discrete and separate intervals via the injection tools 122 and the hydrocarbons 128 may subsequently be produced from multiple intervals or “pay zones” of the formation 108 via isolated production tools 124 arranged along the production tubing 120 b.

In example operation of the well system 100, the heated fluid 124 may be conveyed into the injection tubing 120 a and discharged into the surrounding formation 108 via the injection tools 122. The heated fluid 124 warms the hydrocarbons 128 present within the formation 108 and thereby reduces their viscosity, which allows the warmed hydrocarbons 128 to flow toward the producer wellbore 114. In some cases, the warmed hydrocarbons 128 flow through the formation 108 under the force of gravity. In other cases, however, the production tubing 120 b may maintain an internal bore pressure (e.g., a pressure differential) that draws the hydrocarbons 128 into the production tubing 120 b through the production tools 126. The warmed hydrocarbons 128 may thereafter be pumped (flowed) out of the producer wellbore 114 via the production tubing 120 b.

As the heated fluid 124 is conveyed downhole through the injection tubing 120 a, and as the warmed hydrocarbons 128 are pumped to the surface within the production tubing 102 b, heat is continuously lost to the surrounding formation 108. Such heat losses decrease the effectiveness of the heated fluid 124, which can adversely affect hydrocarbon production as well as increase the energy needed to regenerate the heated fluid on the surface for re-injection. According to embodiments of the present disclosure, heat loss from one or both of the injection and production tubings 120 a,b can be mitigated or minimized by making all or a portion of the injection and production tubings 120 a,b out of vacuum insulated tubing (VIT).

FIG. 2 is a cross-sectional side view of an example length of VIT 200, in accordance with one or more embodiments of the disclosure. As illustrated, the VIT 200 includes an inner pipe 202 a and an outer pipe 202 b, and the inner and outer pipes 202 a,b are concentrically positioned such that an annulus 204 is defined therebetween. The inner and outer pipes 202 a,b may be made of any suitable material used in downhole applications for the exploration and production of hydrocarbons. In at least one embodiment, for example, the inner and outer pipes 202 a,b may be made of steel, such as carbon steel or mild steel. In other embodiments, however, one or both of the inner and outer pipes 202 a,b may be made of other materials, such as stainless steel. The thickness of the inner and outer pipes 202 a,b and the depth of the annulus 204 may vary, depending on the application. Accordingly, it is contemplated herein that the thickness of the inner and outer pipes 202 a,b and the depth of the annulus 204 many span practically any dimension to meet a particular application, without departing from the scope of the disclosure.

The inner and outer pipes 202 a,b may be sealed to each other to isolate the annulus 204. In some embodiments, for example, sealing the inner and outer pipes 202 a,b may be accomplished through the application of one or more welds 206 provided at or near the ends of the pipes 202 a,b. In other embodiments, however, the inner and outer pipes 202 a,b may be threaded to one another to achieve a sealed interface. Once the inner and outer pipes 202 a,b are sealed to each other, a vacuum may be drawn within the annulus 204 to minimize both gas convection and conduction heat transfer between the inner and outer pipes 202 a,b. As a result, heat loss to the surrounding environment may be reduced significantly.

Once the vacuum has been established within the annulus 204, however, it must be maintained or the insulative capacity of the VIT 200 will diminish. More specifically, there is a tendency for molecules such as hydrogen (and/or other active gases) to be desorbed from the metal matrix of the inner and outer pipes 202 a,b, and during oil production, corrosion of the inner and outer pipes 202 a,b can generate additional hydrogen. Migration of the hydrogen into the annulus 204 diminishes the insulative capacity of the VIT 200. In embodiments where the inner and outer pipes 202 a,b are made of steel (e.g., carbon steel, mild steel, etc.), the pipe material will have a body centered cubic matrix structure that makes them more open as compared to aluminum, lead, etc. The body centered cubic matrix structure also makes the inner and outer pipes 202 a,b susceptible to gas diffusion, and this is only enhanced when the material of the inner and outer pipes 202 a,b is heated during operation and the lattice structure correspondingly expands.

Because of its small size, the hydrogen ion is able to achieve rapid interstitial diffusion through most metals, such as steel. As a result, hydrogen can move in and around the atomic matrix structure of the steel inner and outer pipes 202 a,b and no exchange in lattice positions need occur. In order for hydrogen to diffuse through the metal matrix, however, it must first be absorbed. During gas phase absorption, a hydrogen molecule dissociates at the metal surface creating two absorbed hydrogen atoms (H+). Once the hydrogen atoms are absorbed onto the metal surface, they may either become absorbed into the metal matrix or recombine with neighboring hydrogen atoms to form hydrogen gas (H₂). Hydrogen gas is a molecule that is too large to become absorbed, and so it bubbles off into solution or diffuses back into the gas phase. If hydrogen atoms (H+) are absorbed into the metal, however, they then diffuse from the entering to the exit surfaces where they become desorbed into the evacuated annulus 204. The same reactions govern desorption as do absorption, only they occur in reverse, therefore the (H+)+(H+) become hydrogen gas (H₂).

In the case of the VIT 200, hydrogen may be able to migrate through one or both of the inner or outer pipes 202 a,b to access the annulus 204. According to embodiments of the present disclosure, one or more surfaces of the VIT 200 may include or be covered with a coating that reduces the rate of hydrogen permeation (migration) and, therefore, increases the duration of time to failure of the VIT 200. In the illustrated embodiment, for example, a first coating 208 a is applied to the inner surface of the inner pipe 202 a, and a second coating 208 b is applied to the outer surface of the outer pipe 202 b. The VIT 200 may include one or both of the first and second coatings 208 a,b. While not shown, however, it is also contemplated herein that additional coatings may be provided on the inner walls of the annulus 204; e.g., the outer surface of the inner pipe 202 a and/or the inner surface of the outer pipe 202 b, without departing from the scope of the disclosure.

The coatings 208 a,b may be applied to desired surfaces of the VIT 200 via a variety of processes including, but not limited to, spraying, rolling, chemical vapor deposition (CVP), dipping, or any combination thereof. Generally, the coatings 208 a,b may be applied to desired surfaces of the VIT 200 via any process that might be used to apply a paint to a substrate or surface.

The coatings 208 a,b may be configured to reduce hydrogen permeation (migration) through the inner and/or outer pipes 202 a,b by changing the effective minimum spacing relative to the carbon steel lattice spacing of the pipes 202 a,b such that it reduces the probability of hydrogen ions (H+) getting through the steel walls. The coatings 208 a,b may also prove advantageous in preventing or otherwise reducing corrosion of the pipes 202 a,b, which is required to provide the electrons needed for the H+ to become H₂ within the annulus 204.

In some embodiments, the coatings 208 a,b may comprise hydrocarbon-based coatings such as polymer or acrylic-based paints, or an epoxy that is formulated to withstand the application conditions (e.g., temperature, pressure, and environment where the VIT 200 is installed or employed). These formulations can contain metals or other non-hydrocarbon components in order to provide stability to the overall hydrocarbon-based coating for the application environment. Suitable hydrocarbon-based coatings include, but are not limited to, an epoxy, a paint, polyurethane, urethane, acrylic, a resin, a wax, or any combination thereof.

In at least one embodiment, one or both of the coatings 208 a,b may comprise aluminum. In such embodiments, the aluminum material may be sprayed onto one or both of the pipes 202 a,b.

In some embodiments, the VIT 200 may include one or more centralizers 210 attached to an outer surface of the outer pipe 202 b. The centralizers 210 may prove advantageous in helping to protect the second or outer coating 208 b. More specifically, the second coating 208 b may be susceptible to being physically removed from the external surface of the outer pipe 202 b by contacting inner walls of a wellbore as the VIT 200 is lowered or raised within the wellbore. The centralizers 210 provide a radial offset that prevents the second coating 208 b from coming into contact with the inner walls of the wellbore, and thus help to maintain mechanical integrity of the second coating 208 b.

It should be noted that the coatings 208 a,b are not “clad” to the pipes 202 a,b and do not otherwise constitute a “cladding.” Cladding is a chemical attachment means and comprises the bonding together of dissimilar metals through various techniques, such as electroplating. While cladding may help reduce corrosion, cladding fails to change the hydrogen permeation structure or the gaps in the lattice structure where H+ can pass through. In contrast, the coatings 208 a,b are applied as a mechanical attachment, often applied as a spray that contacts and adheres to the underlying surfaces of the pipes 202 a,b. Moreover, the coatings 208 a,b help change the lattice structure orientation and thereby tighten (i.e., decrease the size of) the gaps in the lattice structure of the pipes 202 a,b, which helps prevent hydrogen permeation (migration).

Hydrocarbon-based coatings similar to the coatings 208 a,b have not been previously used in VIT in favor of the more traditional cladding via electroplating. Hydrocarbon-based coatings have finite temperature limits before they start to chemically break down, thus such coatings are generally viewed as not being able to withstand the operating temperatures of a downhole thermal recovery application since they are not generally rated for the required temperature. However, while the vacuum insulation of the present disclosure remains integral, the coatings 208 a,b applied to one or more surfaces of the VIT 200 do not necessarily see (experience) the full design temperature of the internal fluid in the annulus and therefore are not expected to experience accelerated degradation. There also may be some thermal applications where hydrocarbon-based coating can withstand the internal temperatures of the thermal operation.

As indicated above, the principles disclosed herein may alternatively be applied to any subsurface process that transports fluids at elevated temperatures, such as any geothermal application that may benefit from the use of the VIT 200. For example, the VIT 200 may be used in any injection or production geothermal well to help reduce heat loss to the overburden as heated fluids are injected into, or produced from, subterranean formations.

Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.

The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well. 

What is claimed is:
 1. A vacuum insulated tubing, comprising: an inner pipe; an outer pipe concentrically arranged about the inner pipe such that an annulus is defined between the inner and outer pipes; a vacuum drawn within the annulus; and a hydrocarbon-based coating applied to at least one of an inner surface of the inner pipe or an outer surface of the outer pipe to reduce a rate of hydrogen migration into the annulus.
 2. The vacuum insulated tubing of claim 1, wherein the hydrocarbon-based coating is selected from the group consisting of an epoxy, a paint, polyurethane, urethane, acrylic, a resin, a wax, and any combination thereof.
 3. The vacuum insulated tubing of claim 1, wherein the hydrocarbon-based coating is further applied to at least one inner wall of the annulus.
 4. The vacuum insulated tubing of claim 1, wherein the inner and outer pipes are made of a material selected from the group consisting of carbon steel, mild steel, stainless steel, any alloy thereof, and any combination thereof.
 5. The vacuum insulated tubing of claim 4, wherein the inner and outer pipes are made of carbon steel.
 6. The vacuum insulated tubing of claim 1, further comprising one or more centralizers attached to the outer surface of the outer pipe.
 7. A method, comprising: flowing a heated fluid through a vacuum insulated tubing that includes: an inner pipe and an outer pipe concentrically arranged such that an annulus is defined between the inner and outer pipes; a vacuum drawn within the annulus to create an evacuated annulus; and a hydrocarbon-based coating applied to at least one of an inner surface of the inner pipe or an outer surface of the outer pipe; preventing heat loss from the vacuum insulated tubing to a surrounding environment with the evacuated annulus; and reducing a rate of hydrogen migration into the evacuated annulus with the hydrocarbon-based coating.
 8. The method of claim 7, wherein reducing the rate of hydrogen migration into the evacuated annulus comprises changing a minimum spacing in the chemical lattice structure of one or both or the inner and outer pipes with the hydrocarbon-based coating and thereby reducing a rate of hydrogen ions traversing a wall of the inner or outer pipes on which the hydrocarbon-based coating has been applied to its surface.
 9. The method of claim 7, wherein the hydrocarbon-based coating is applied to the outer surface of the outer pipe, the method further comprising protecting the hydrocarbon-based coating from damage with one or more centralizers attached to the outer surface of the outer pipe.
 10. The method of claim 8, wherein reducing the rate of hydrogen migration into the evacuated annulus comprises limiting corrosion of one or both or the inner and outer pipes with the hydrocarbon-based coating.
 11. The method of claim 8, wherein the hydrocarbon-based coating is selected from the group consisting of an epoxy, a paint, polyurethane, urethane, acrylic, a resin, a wax, and any combination thereof.
 12. The method of claim 8, wherein the inner and outer pipes are made of a material selected from the group consisting of carbon steel, mild steel, stainless steel, any alloy thereof, and any combination thereof.
 13. The method of claim 12, wherein the inner and outer pipes are made of carbon steel.
 14. The method of claim 8, further comprising flowing the heated fluid through the vacuum insulated tubing in a thermal recovery technique selected from the group consisting of steam assisted gravity drainage, expanding solvent steam assisted gravity drainage, steam flooding, steam drive, cyclic steam stimulation, liquid addition to steam for enhancing recovery with cyclic steam stimulation, heated light hydrocarbon injection, vapor extraction, heated vapor extraction, cyclic solvent processing, thermal-solvent injection, geothermal, and any combination thereof.
 15. The method of claim 14, wherein the heated fluid is a fluid selected from the group consisting of steam, water, an oil, a solvent, carbon dioxide, methane, a light hydrocarbon, nitrogen, any fluid that contains a hydrogen atom, and any combination thereof.
 16. The method of claim 14, wherein the vacuum insulated tubing (VIT) is a first VIT extended into an injector wellbore, the method further comprising: discharging the heated fluid from the first VIT and into a surrounding subterranean formation; and heating oil present within the surrounding subterranean formation with the heated fluid.
 17. The method of claim 16, further comprising: drawing the oil into the injector wellbore and conveying the oil to a surface location; and preventing heat loss from the injector wellbore to the surrounding environment with the evacuated annulus as the oil travels to the surface location.
 18. The method of claim 16, further comprising: flowing the oil in the surrounding subterranean formation toward a second VIT extended into a production wellbore, the second VIT including: a production inner pipe and a production outer pipe concentrically arranged such that an annulus is defined between the production inner and outer pipes; a vacuum drawn within the annulus defined between the production inner and outer pipes to create a production evacuated annulus; and the hydrocarbon-based coating applied to at least one of an inner surface of the production inner pipe and an outer surface of the production outer pipe; receiving the oil within the second VIT and conveying the oil to a surface location; preventing heat loss to the surrounding environment with the production evacuated annulus; and reducing the rate of hydrogen migration into the production evacuated annulus with the hydrocarbon-based coating.
 19. The method of claim 8, wherein flowing the heated fluid through the vacuum insulated tubing comprises flowing the heated fluid to or from a subterranean formation in a geothermal application.
 20. A well system, comprising: a tubing extending within a wellbore, wherein at least a portion of the tubing comprises vacuum insulated tubing that includes: an inner pipe and an outer pipe concentrically arranged such that an annulus is defined between the inner and outer pipes; a vacuum drawn within the annulus; and a hydrocarbon-based coating applied to at least one of an inner surface of the inner pipe and an outer surface of the outer pipe, wherein the hydrocarbon-based coating operates to reduce a rate of hydrogen migration into the annulus.
 21. The well system of claim 20, wherein the tubing is used in a thermal hydrocarbon recovery technique selected from the group consisting of steam assisted gravity drainage, expanding solvent steam assisted gravity drainage, steam flooding, steam drive, cyclic steam stimulation, liquid addition to steam for enhancing recovery with cyclic steam stimulation, heated light hydrocarbon injection, vapor extraction, heated vapor extraction, cyclic solvent processing, thermal-solvent injection, geothermal, and any combination thereof.
 22. The well system of claim 20, wherein the hydrocarbon-based coating is further applied to at least one inner wall of the annulus.
 23. The well system of claim 20, wherein the inner and outer pipes are made of a material selected from the group consisting of carbon steel, mild steel, stainless steel, any alloy thereof, and any combination thereof.
 24. The well system of claim 23, wherein the inner and outer pipes are made of carbon steel.
 25. The well system of claim 20, wherein the hydrocarbon-based coating is selected from the group consisting of an epoxy, a paint, polyurethane, urethane, acrylic, a resin, a wax, or any combination thereof.
 26. The well system of claim 20, wherein the wellbore is an injector wellbore and the tubing is an injector tubing used in a steam assisted gravity drainage application, the well system further comprising: a production wellbore extending from the surface location and having a portion extending parallel to and vertically offset from a corresponding portion of the injection wellbore; a production tubing extending within the production wellbore, wherein at least a portion of the production tubing comprises VIT comprising: a production inner pipe and a production outer pipe concentrically arranged such that an annulus is defined between the production inner and outer pipes; a vacuum drawn within the annulus defined between the production inner and outer pipes; and the hydrocarbon-based coating applied to at least one of a surface of the production inner pipe or a surface of the production outer pipe.
 27. The well system of claim 20, further comprising one or more centralizers attached to the outer surface of the outer pipe. 